Method for increasing the net present value of fuel production while producing low sulfur fuels

ABSTRACT

A method is provided for increasing the net present value of fuel production while reducing the sulfur content of one or more fuel products produced in a refinery. The method includes converting at least one existing reformer into a hydrodesulfurization system; and replacing the at least one hydrocarbon reformer with a continuous catalytic reformer.

1.0 FIELD OF THE INVENTION

[0001] The present invention relates to the field of petroleum refining.In particular, the invention relates a method of producing low sulfurgasoline (LSG) and ultra low sulfur diesel (ULSD) which maximizes thenet present value of the gasoline produced by a refinery.

2.0 BACKGROUND

[0002] The process of refining petroleum into gasoline, diesel fuel andother products is widely practiced throughout the world. In general,this process involves distilling of crude oil into a variety ofhydrocarbon fractions, reforming or purifying at least some of thefractions to improve their performance characteristics for theirintended use, and, optionally, blending the fractions into marketablefuel products.

[0003] Sulfur containing compounds are significant impurities in boththe crude oil and the distillation fractions, and their removal hasbecome particularly important in recent years. New federal environmentalregulations have imposed strict standards for lowering the sulfurcontent of both gasoline and diesel sold and used in the United States.Similar standards are already in place in parts of Europe and inCalifornia. In short, to meet these standards, the sulfur content ofgasoline must be reduced to 30 ppm (parts per million), while the sulfurcontent of diesel fuel must be reduced to 15 ppm under the comingregulatory scheme.

[0004] Even without these regulatory requirements, the removal of sulfurimpurities is highly desirable for a number of reasons. Such impuritiescan degrade catalysts and corrode machinery in later reforming/blendingsteps. Moreover, they may also produce a noxious smell when used incombustion engines, as well as contribute to environmental problems suchas acid rain.

[0005] There are a number of technologies that can be used to removethese impurities from the hydrocarbon fractions during the refiningprocess. These technologies usually involve “hydrogenation”, thecatalytic addition of hydrogen molecules to the sulfur impurities toform compounds with lower boiling points (e.g., H₂S). These compoundscan then be removed from the hydrocarbon stream.

[0006] While these technologies are widely known, upgrading a refineryto include units employing them can be extremely expensive, requiringall new reactors, catalyst beds, piping, heaters, towers and otherequipment and infrastructure. Also, the construction of new reactors,beds, and the like may represent an inordinate cost to some refineryoperators, especially in light of the limited profit margins availablein the commercial distribution and sale of gasoline and diesel fuel. Asa result, many refineries are economically constrained with respect totheir current infrastructures, and capital expenses and costs toimplement desulfurization technologies are eventually borne by eitherthe retailers, consumers, or the refineries' shareholders.

[0007] Thus, there is a need in the art for a method of implementingsulfur reducing technologies to produce LSG and ULSD while increasingthe net present value of fuel production in current petroleumrefineries.

3.0 SUMMARY OF THE INVENTION

[0008] The present invention relates a method of producing LSG and ULSDwhile increasing the net present value of fuel production by selectivelyconverting existing reformers within the refinery intohydrodesulfurization units, and replacing the converted reformers unitswith modern units. This results in an increase in the amount of gasolineproduced by the refinery, an increase in the amount of high octane ratedcontent produced by the refinery from the hydrocarbon fractions orstreams derived from the crude petroleum, or both. Thus, the presentinvention allows refinery operators and owners to produce LSG and,optionally, ULSD in a cost effective manner.

[0009] The method involves converting a hydrocarbon reformer into adesulfurization system, and replacing the old reformers with state ofthe art reforming technology. The net present value of the refinery'sproduction capacity increases relative to its first production capacity(e.g. the refinery's production capacity with its pre-conversionreformers, the production capacity following the installation of new HDSunits, and the like) as either an increase in gasoline production volumeor as an increase in the economic value of the fractions or productsproduced therefrom. The net capital cost for the steps of converting andreplacing the at least one hydrocarbon reformer, in light of theincrease in the net present value, is then greater than the net presentvalue of the first production capacity minus a net capital cost forinstalling a new desulfurization system.

[0010] In one embodiment, a continuous catalytic reformer replaces oneor more of the old reformers in the refinery. The continuous catalyticreformer increases the percentage of high octane gasoline or blendablefraction of gasoline product produced per barrel in comparison to thepercentage produced by the refinery using the original hydrocarbonreformer, if any, and a new desulphurization system. The fuel productsproduced by a refinery's desulfurization systems have a sulfur contentwhich has been reduced to a level in compliance with a publishedgovernment standard.

[0011] In one embodiment, the increase in the percentage of high octanegasoline or fraction of gasoline per barrel of crude oil is greater thanabout 5% per barrel. Optionally, this increase in the percentage of highoctane gasoline or fraction of gasoline produced per barrel can bebetween 5% to 27%.

[0012] In one embodiment, at least two catalytic reformer systems areconverted into desulfurization systems, and the net present value of thefuel produced by the refinery using the continuous catalytic reformerand the desulfurization systems, is greater than the net present valueof the fuel produced by the refinery using at least two catalyticreformers prior to their conversion to desulfurization systems. In oneembodiment, the desulfurization system reduces the sulfur content of thegasoline produced by the refinery to about 30 ppm or less. Optionally,the desulfurization system reduces the sulfur content of the diesel fuelproduced by the refinery to about 15 ppm or less.

4.0 BRIEF DESCRIPTION OF THE DRAWINGS

[0013]FIG. 1 depicts a simplified process flow diagram for theconversion of a BTX (benzene, toluene, xylene) reformer unit into agasoline HDS unit.

[0014]FIG. 2 depicts a simplified process flow diagram for theconversion of a Motor reformer unit into a diesel fuel HDS unit.

[0015]FIG. 3 is a chart depicting projected net present value as afunction of increasing diesel fuel and gasoline prices in cents pergallon.

5.0 DETAILED DESCRIPTION

[0016] For the purposes of this disclosure, the terms “petroleum” and“crude oil” are interchangeably used to refer to the complex mixture ofhydrocarbons obtained from oil fields. Depending on its geographicsource, crude oil may contain about 35% to 65% (by volume) saturatedhydrocarbons and olefins, 5% to 25% aromatics, 15% to 55% naphthenes,and about 0.2 to 3% sulfur (% wt).

[0017] The terms “sulfur compounds” and “sulfur impurities” refer to theelemental sulfur and sulfur containing organic compounds found in crudeoil and distillation fractions, which generally include, but are notlimited to, hydrogen sulfide and sulfur containing hydrocarbons such assulfides, thiols, and thiophenes.

[0018] The terms “distillation” and “fractionation” are alternativelyused to refer to the step in the refining process separating crude oilinto various fractions. Each hydrocarbon fraction thus produced has itsown characteristic boiling point range, and can be generally classifiedas low boiling point fractions, middle boiling point fractions, or highboiling point fractions. Low boiling point fractions generally includelow boiling point hydrocarbons such as methane, ethane, and propane.Middle boiling point fractions generally include (or may be used toproduce) naphthas, kerosene, benzene, toluene, naphthalene, anddistillate fuels (i.e. diesel fuel, virgin fuel oil, and virgin heatingoil). The high boiling point fractions include (or maybe used toproduce) lubricating oils and tars, and the residue or bottom fractioncontains tar and coke.

[0019] The term “naphtha” is used to refer to the middle boiling rangehydrocarbon fraction or fractions that are major components of gasoline,while the terms FCC naphtha and FCC gasoline refer to naphtha which hasbeen produced by the process of fluid catalytic cracking.

[0020] The terms “feed” and “feedstream” refer to the stream being sentto a reactor or treatment process while the terms “product stream” and“outlet stream” refer to the stream after it leaves the reactor. In arefinery, a hydrocarbon fraction may be referred to as both a feedstockand reaction product when between multiple steps in a treatment process.For example, the outlet stream of a diolefin treater may become the feedfor blending gasoline.

[0021] The term “reforming” refers to processes of thermally orcatalytically converting hydrocarbon fractions into fractions havingimproved characteristics (e.g., a higher octane rating). Reformingencompasses processes that include cracking, polymerization,hydrotreating, dehydrogenation and isomerization reactions used toimprove or convert hydrocarbon fractions into higher octane fractions.The term reformate refers to a hydrocarbon reaction product which hasbeen subjected to one or more reforming steps.

[0022] The term “cracking” refers to the process of breaking highermolecular weight (MW) hydrocarbon molecules into lower MW molecules,typically in the presence of a catalyst. In the refining process,cracking may be performed with reaction conditions including elevatedtemperatures, elevated pressure, the presence of a catalyst or acombination of these parameters.

[0023] The term “desulfurization” refers to any of the several processesof chemically removing sulfur compounds from hydrocarbon fractions.Hydrodesulfurization is an example of these processes, as well as anexample of catalytic hydrotreating. Hydrodesulfurization typically usesa catalyst and hydrogen gas to remove sulfur impurities by convertingthem to H₂S and lower molecular weight compound. Hydrotreating processesmay also be used to remove nitrogen containing compounds (e.g. amines,amides, etc.).

[0024] The term “blending” as used herein, refers to the process ofmixing different hydrocarbon fractions into a single product, typicallythe mixing of naphtha with reformates and raffinates or otherhydrocarbon fractions to produce a gasoline product with a predeterminedoctane rating (an anti-knock rating system), vapor pressure, or otherdesirable characteristic. Blending may take place at the refinery, thegasoline retailer, or even at the gas pump at a gas station.

[0025] The term “light straight run” (LSR) refers to the low to midrange boiling point hydrocarbon fractions taken directly from a sidestream off the crude distillation column or downstream column if aseries of distillation columns is used. An LSR also typically containssulfur impurities.

[0026] The term “net present value” (NPV) refers to the sum of thepresent values of future income (e.g. net income per year). To reduce afuture income to a present value, a discount rate representing, interalia, the lost opportunity costs of an investment, is applied to thefuture income according to the following formula:

NPV=I ₀ +I _(n)/(1+r)^(n)

[0027] Here, “I” represents the net yearly income obtained from theinvestment. “I” may also be negative, e.g. when capital expenditure,losses, or operating costs are greater than income for a given year. The“r” represents the discount rate, and the “n” represents the year of theincome.

[0028] In the present invention, an NPV was estimated for severalrefinery unit additions and modifications, with regard to meeting theupcoming LSG and USLD regulations, including the addition of new units,the conversion of existing units to new uses, and upgrading equipmentwhere appropriate. The NPVs were calculated 15 year terms and includingthe net initial installation costs

[0029] To effectively perform this analysis, several assumptions andexclusions were made where appropriate in order to ensure theconsistency of the comparisons, and in order to estimate the costs andincome associated with each unit addition or modification. Theseassumptions include, for the reform-to-HDS conversion examples, that anew continuous catalytic reformer is also installed to replace theconverted reformers, with an estimated initial investment ofapproximately $160 million dollars based on past installation costs forcomparable reformers. The assumptions also include that all existingequipment and infrastructure in the reformers being converted are ingood and working condition. Also, the NPV estimates for converting thereformers were made based upon fiscal year 2001 budget prices, whilefuture income estimates assumed a 20% tax rate as well as a 12% discountrate. It is understood that these and other assumptions/exclusions inthe analysis may be made, as long as consistency is maintained betweenthe comparisons, particularly the comparisons of the NPVs associatedwith converting existing units to the NPVs of installing new units.

[0030] The main process operating conditions for both the LSG and ULSDHDS systems were also estimated in order to guide the selection ofmaterials and equipment. The LSG HDS main process operating conditions,such as reactor temperatures, pressures, hydrogen purity, etc, werebased on engineering studies performed for existing refineries, and onreviews of existing Mobil desulfurization technologies. Desulfurizationtechnologies reviewed included

[0031] Exxon Mobil SCANFining IFP and Prime G⁺. In short, the mainprocess operating conditions were 350 psig (pounds per square inch gage)reactor pressure, 700° F. end-of-run temperature, 75% hydrogen purity,and 2.0 LHSV (liquid hourly space velocity).

[0032] The ULSD HDS main process operating conditions were basedprimarily on studies published by the National Petroleum Conference(June 2000) and published data. In short, the main process operatingconditions were 800 psig reactor pressure, 750° F. end of runtemperature, 75% hydrogen purity, and 1.0 LHSV. For both the LSG andULSD conversions, current equipment and piping materials in each casewere evaluated for use with these process conditions.

[0033] The capital cost estimates for converting the existing reformersin particular were derived from engineering studies which determinedwhat equipment and material were required to convert two gasolinereformer units into desulfurization treatment units. The equipment andmaterial included as part of the estimates for each example includes,for example, but without limitation, new or modified reactors, towers,vessels/drums, heaters, heat exchangers, pumps, and compressors. Flowdiagrams for the converted, reformer-to-hydrodesulfurization units (HDS)are disclosed herein in FIG. 1 and FIG. 2.

6.0 EXAMPLES 6.1. Conversion of Existing Reformers and Installation of aContinuous Catalytic Reformer

[0034] The conversion of existing reformer units into HDS units may bemade with only minor modifications as described below. The HDS unitsgenerally follow typical HDS process flows. In these process flows, afeed is mixed with hydrogen gas (e.g., recycled hydrogen and make-uphydrogen.) The feed is then heated to reactor inlet conditions by heatexchange with the hot reactor outlet stream, by heat provided by a feedheater, or both. The feed then travels to one or more reactors, wheredesulfurization occurs. The now hot product stream (i.e. the outletstream) is routed back to the heat exchanger in order to heat thereactor feed. An air cooler reduces the temperature of the reactoreffluent, and the liquid and vapor phases are separated in a lowtemperature, high pressure separator. The liquid is sent to a stabilizerand the H₂ vapor to an amine tower, which removes the H₂S in the H₂vapor.

[0035] The vapor can then be returned to the hydrogen recycle stream.Installation of a new amine scrubber is included in the followingconversions, but it is recognized that some refineries may be able touse existing scrubber systems. Moreover, it is understood thatalternative process flows may be used, in either the new HDS units or inthe converted reformer HDS units, depending in part on the refineriesexisting equipment, available infrastructure or particular needs. It isalso understood that the installation of metallurgical upgrades in theconversion of reformers to HDS units (hereinafter referred to as “aconversion”) can in some instances be delayed, thus reducing initialinstallation costs. However, increased monitoring would then be requiredto ensure that the higher sulfur content in the feed and increasedprocess temperatures and pressures do not impair the function of thepiping or equipment, or cause excessive corrosion thereof.

6.1.1. Example 1

[0036] Referring to FIG. 1, a BTX reformer with an approximate maximumcapacity of 30,000 Bbl/day of light naphtha, dehexanizer bottoms andlight unicrackate, was analyzed for conversion into an HDS unit runningapproximately 42,000 Bbl/day of FCC naphtha to produce LSG or highoctane gasoline fractions (e.g. a high octane pool). This conversionrequires several expansions and additions to the current unit, alongwith some material upgrades due to higher H₂S concentrations in thereactor effluent stream. A summary of the costs for this conversion islisted in Table 1 below. TABLE 1 Modification or Addition Cost Estimate% of Total Cost Estimate New stabilizer tower trays $2.5 MM 13% Newamine tower $1.5 MM  8% New diolefin reactor $1.5 MM  8% 6 newexchangers $3.5 MM 18% Modified recycle $1.5 MM  8% compressor MaterialUpgrades $3 MM 15% % of Total 70%

[0037] The total estimated costs for this conversion is about $20million. As seen in Table 1, the majority of the costs in Example 1 aredue to new equipment and material upgrades. These material upgradesinclude relining reactors, material changes on the tube and shell sideof heat exchangers, and piping changes to prevent or reduce corrosion.

[0038]FIG. 1 depicts a simplified process flow diagram depicting theplacement of reactors, towers, heat exchangers, pumps and compressors inthe converted unit, particularly those newly installed or requiringmaterial upgrades for the conversion.

[0039] Reactors

[0040] Prior to conversion into a hydrotreating unit, the BTX reformerpretreated its liquid feedstock to remove sulfur. Before the liquidfeedstock and hydrogen mix were fed into existing reactors they weretreated at a hydro pretreater 30 for desulfurization. The pretreaterreactor 30 was used to prevent reformer catalyst fouling by removingsulfur compounds. From the pretreater reactor 30, it was then fed to theBTX reformer reactors 34.

[0041] The prior to conversion, the BTX reformer reactors 34 includefour spherical reactors made of 1¼ Cr (chromium steel). The conversionentails, in this instance, lining the BTX reformer reactors with 321stainless steel (ss). The piping between the reactors and hotfeed/effluent exchangers are also lined or replaced with 321 ss.

[0042] Towers

[0043] The BTX reformer's stabilizer tower 38 requires a partial retrayfor the design gas and liquid flows. The top 1′of the tower 38preferably is lined with 316 ss, and contains a 347 ss distributor. Therest of tower 38 may be carbon steel (C Stl). The conversion in thisinstance also requires addition of a new amine scrubber tower 42., whichalso may be made of C Stl.

[0044] Vessels/Drums

[0045] The BTX unit includes a feed surge drum 46 and a stabilizerreflux drum 54. These drums will remain in the conversion. Theconversion also includes modification of the effluent separator 50. Washwater may be needed to remove scale from the effluent coolers, thus awasher boot (not depicted) will also be installed in the conversion.

[0046] The conversion also includes three new drums. Because of theaddition of amine tower 42, the conversion includes a new carbon steel,vertical knockout drum (not depicted) with a 316 ss demister. Theconversion also includes a new 230 ft²H₂/Cl bed 58 to remove catalystpoisons from the make-up hydrogen. The third drum is degassing drum 62,which is fed by the amine scrubber tower 42 bottoms.

[0047] Heaters

[0048] The BTX reformer employs four heaters, but only two will beneeded for the conversion to an HDS unit. Heaters 70, 74 supply a firedduty of 68 MMBtu/hr and 42 MMBtu/hr respectively. For the conversion,the first heater 70 is modified for use as a stabilizer reboiler heater,and its burners are modified for an absorbed duty of 28 MMBtu/hr.

[0049] The second heater 74 may optionally be used as a reactorpreheater, but a retube may be required due to the need for a materialupgrade. In particular, higher sulfur content in the feed may requirethat the heater be retubed, and the piping between heater 74 and thereactors be replaced with 9 Cr.

[0050] Heat Exchangers

[0051] In the conversion, the four BTX cold feed/effluent exchangers 78meet the duty requirements for the HDS unit, but the tubes shouldpreferably be upgraded to 321 ss due to H₂S in the effluent. Conversionof the hot feed/effluent exchangers 82 also preferably includes a tubereplacement with 321 ss in the conversion, along with a shell upgradesto 321 ss. The duty requirements for the HDS units are not met with thisset of the BTX units exchangers, so an additional exchanger (notdepicted) is added in the conversion.

[0052] Stabilizer feed/bottom exchanger 86 needs no modifications forthe conversion, but may preferably be modified to provide additionalsurface area. An additional 10,000 ft² can be added in parallel withexchanger 86 by adding three new exchangers (not depicted) made of CStl. Two new exchangers will also be added to the stabilizer bottomscooler 100 to provide an additional 9,600 Btu/hr. The stabilizerreboiler exchanger (not depicted) and the surface condenser (notdepicted) are abandoned in the conversion, but the rest of the existingexchangers may remain in service without modification, includingstabilizer condenser 94 and effluent condenser 98.

[0053] Pumps

[0054] The BTX unit's feed pump 104 has a rated capacity of 900 gpm(gallons per minute), but the additional volume provided to the HDS unitin the conversion will require 1260 gpm. A 500 HP motor is installed inthe conversion of the reformer's feed pump to meet the HDS requirements.The BTX unit's stabilizer reflux pump 108 meets all the requirements forthe HDS unit, and the surface condenser condensation pump (not depicted)is no longer needed. Two new pumps 112, 116 plus two backup pumps (notdepicted) are also included in the conversion. A centrifugal pump 112 isadded for the conversion of the stabilizer reboiler into a heater, and apiston pump 116 is added for the wash water.

[0055] Compressors

[0056] The conversion includes modifications to the recycle compressor120. The reformer's recycle compressor 120 is a five stage centrifugalcompressor, with a 10,000 HP motor. This compressor is larger thannecessary for the HDS unit, and may be destaged to replace the steamdriver with a 4000 HP motor.

6.1.2. Example 2

[0057] The BTX reformer of Example 1 was also analyzed for conversioninto an HDS unit, processing an additional LSR feed. The feed in thisexample includes 42,000 Bbl/day of FCC naphtha and about 10,000 Bbl/dayof LSR. However, a splitter unit (not depicted) is included in theconversion upstream from the HDS reactors, producing gasoline and fuelgas fractions.

[0058] A 30/70 split was assumed for the feed, therefore, only 30,000Bbl/day of FCC naphtha will be hydrotreated.

[0059] A summary the costs for this conversion is contained in Table 2below. TABLE 2 Modification or Addition Cost Estimate % of Total CostEstimate 2 New splitters (splitter $6.5 MM 22% unit) 4 New exchangers$1.5 MM  5% (splitter unit) New pumps (splitter unit) $3 MM 10% Materialupgrades $5 M 17% (splitter unit) New diolefin reactor $1.5 MM  5% (HDSunit) Modified recycle $1 MM  3% compressor (HDS unit) New amine tower$1 MM  3% (HDS unit) Material Upgrades $7 MM 23% (HDS unit) % of Total88%

[0060] The total cost estimate for Example 2 is $30 million dollars, aslightly higher figure than that for Example 1. As seen in Table 2, theadditional feed requires the installation of a splitter and itsancillary equipment. The splitter costs amount to approximately 45% ofthe estimated cost, whereas the other 55% is due to modifications andsome new equipment for the desulfurization portion of the unit. Here,the lower volume entering the HDS reactors reduced the number ofmodifications to be made in this portion of the unit.

6.1.3. Example 3: Modification of a Motor Reformer

[0061] The reformer in this example was originally designed to process amaximum of 18,000 Bbl/day of heavy unicrackate and some light naphtha.The modified hydrotreater unit, will run 15,000 Bbl/day of VFO to beprocessed into ULSD. High reactor pressures and low space velocitieswill require expansions and additions to the current unit along withsome material upgrades. The estimated cost for this conversion is $20million dollars. As seen in Table 3 below, approximately half of theestimated costs for Example 3 stem from the installation of a new HDSreactor. TABLE 3 Modification or Addition Cost Estimate % of Total CostEstimate New HDS reactor $9 MM 45% New H₂ make-up $2 MM 10% compressorMaterial upgrades $2.5 MM 13% % of Total 68%

[0062] The current reformer's reactors do not have the capacity for theHDS unit, and were not the proper material. Therefore, all of theoriginal reactors were replaced with one new reactor meeting all the HDSunit criteria. Again, material upgrades are mainly due to the highpressure, high temperature hydrotreater loops and higher sulfur contentin the feeds. The ULSD HDS temperature and pressure operating conditionsare also higher than current conditions in the reformer; therefore, theconversion preferably includes the replacement of a number of metalcomponents with higher grade metal.

[0063]FIG. 2 is a simplified process flow diagram depicting theplacement of reactors, towers, heat exchangers, pumps and compressors,particularly those newly installed or requiring material upgrades.

[0064] Reactors

[0065] The Motor reformer unit has five small vertical reactors. In thisinstance, the reactors are too small to meet the needs for the HDS unit,and would all require a lining upgrade to 321 ss. Thus, in this example,it is more cost effective to replace all of the reformer's reactors witha new HDS reactor 124. The HDS reactor 124 has 2 beds, and a 347 ssdistributor. Due to high sulfur content in the feed, the reactor will bemade of 1¼ Cr and will be 321 ss lined. Preferably, 321 ss pipingbetween the reactors and the feed/effluent exchangers should also beinstalled. Unlike Example 1, no SHU reactor is included for Example 3.

[0066] Towers

[0067] The conversion includes no modifications to existing towers.However, an amine scrubber 128 is added as described above.

[0068] Vessels/Drums

[0069] All existing drums and vessels will be utilized for theconversion. No modifications are needed for the charge drum (notdepicted), steam drum (not depicted), reactor product separator (notdepicted), and the steam separator (not depicted). The conversion doesinclude installing a water boot in the stabilizer overhead. Three newvessels and drums will be required as in Example 1, a compressorknockout drum (not depicted), and H₂/Cl guard bed 136, and an aminedegassing pot 140.

[0070] Heaters

[0071] The reformer has four heaters 146, but due to the exothermicnature of the HDS reaction, only one heater is used in the HDS system,providing a fired duty of 57,000 Btu/hr. The heater tubes may also beupgraded from 2¼ Cr, 1 Mo to 9 Cr.

[0072] Heat Exchangers

[0073] The conversion includes retrofitting the reformer's feed effluentexchangers 144, 148 with a new shell and tube made of 321 ss, since theyare in the high pressure, high temperature hydrotreater loop. The restof the reformer's heat exchangers may be used without modifications.

[0074] Pumps

[0075] The reformer's stabilizer pump (not depicted), overhead pump (notdepicted) and the spare charge pump (not depicted) will need nomodification for the conversion. However, the conversion does includereplacing the motor of the charge pump 152 to increase the horsepowerfrom 400 hp to 500 hp, due to the increased volume of the HDS feedrelative to the reformer's feed.

6.2. Installation of a Continuous Catalytic Reformer

[0076] Examples 1 to 3 above assume that a modem reformer unit is builtto replace the converted reformers. For example, a continuous catalyticreformer (CCR) with a capacity of about 45,000 Bbl/day, may be installedto replace both the Motor reformer and BTX reformer's discussed above.The CCR's annual operating cost is estimated to be about $10 million peryear, and annual maintenance costs of about $3 million per year. Theoperating and maintenance costs of the CCR may be offset by a reductionin maintenance and operating costs of an existing H₂ plant, which can besold or taken off-line. Based on known CCR efficiencies, (capacity andyields), replacing the converted reformers with the CCR results in a $12to $15 million/year increase in revenue. This increase in revenue stemsfrom an estimated 4,500 Bbl/day increase in gasoline production, anincrease in pool octane (the amount of high octane fraction availablefor blending into a gasoline fuel product) and, optionally, an increasein BTX (benzene, toluene, xylene) production. In essence, the modernreformer increases the potential production capacity of gasoline (perbarrel) by more than about 3-5% per barrel. Depending in part on theefficiency and production capacity of the original informer thisincrease my be as much as between about 5% to 27% (per barrel). For theinstallation of a modern and highly efficient continuous catalyticreformer, the increase may be from 60-80% for the existing reformer toabout 90-98% for the high efficiency catalytic cracking reformer.However, it is recognized that these incremental increases in efficiencymay be based on the relative inefficiency of the reformer beingconverted and replaced.

[0077] In the above examples, the summation of the savings, maintenancecosts, operating costs, and improved gasoline production, results in anincrease in yearly refinery income of approximately $12 million dollars.Taking taxes and depreciation into account, as well as the capital costsfor converting the two reformers and installing the CCR, the NPV fromEquation 1 is −88.3 at current gasoline and diesel fuel prices.

6.3. Comparative Example

[0078] The capital investment required to install and bring online newgasoline and diesel hydrodesulfurization systems is summarized brieflyin Table 3 below. TABLE 3 Capital (MM$) 2002 2003 2004 2005 TotalGasoline 10 20 45 0 75 HDS unit Diesel 0 10 20 30 60 HDS unit Total 1030 65 30 135

[0079] In essence, the initial capital cost for installing these twosystems is approximately $135 million, expended over 4 years. Inaddition, starting from year one of operation, a new gasoline HDS unitcosts roughly $8 million dollars per year to operate in order tomaintain current production levels of gasoline (as low sulfur gasoline).A new diesel fuel HDS unit costs $7.5 million per year to operate. Onceoperational, an estimated $2 million would need to be spent on HDS unitmaintenance (based on the historical maintenance costs of currentlyemployed hydrotreating systems). These costs would be offset by a $5million saving increase in revenue per year starting in 2006, as dieselfuel would no longer be treated by the FCC unit, thus creatingdownstream capacity and the potential for incremental crude throughput.Moreover, the HDS units do not produce an increase in gasolineproduction, pool octane, or BTX production. Taking taxes anddepreciation into account as in Example 3, as well as the capitalinvestment costs for installing new HDS units from Table 3, theinstallation results in a decrease in future income of about $12 millionper year. The NPV from Equation 1 in this instance is −132.9, again, atcurrent gasoline and diesel fuel prices.

[0080] Thus, although the $135 million dollar initial capital investmentfor new HDS units does appear to compare favorably to the $200 millionestimated for converting a BTX and Motor reformer into HDS systems andbuilding a modem reformer unit, when the increased yearly income of thelatter method is taken into account, the NPV of the latter method isgreater than the NPV for the new HDS units.

[0081]FIG. 3 is a chart illustrating NPV as a function of an incrementalchange in the price of diesel fuel and gasoline. As seen in FIG. 3, arefinery implementing the inventive method would be able to have a zeronet loss from implementing the new regulations and increasing the priceof gasoline and diesel fuel by only about 1.0 to 1.9 cents per gallon.In contrast, installing HDS systems would require an increase of greaterthan 2 cents per gallon in order for the refinery to break even.

[0082] The foregoing recitation of the invention is offered for thepurposes of illustration only. It is recognized that the embodimentsdescribed herein may be modified or revised in various ways withoutdeparting from the spirit and scope of the invention. Instead, the scopeof the invention is intended to be measured by the appended claims.

What is claimed:
 1. A method for increasing the net present value offuel production while reducing the sulfur content of one or more fuelproducts produced in a refinery having a first production capacity,comprising: converting at least one hydrocarbon reformer into adesulfurization system; and replacing the at least one hydrocarbonreformer with a modem reformer, to form a second production capacity;wherein the net present value of the second production is greater thanthe net present value of the first production capacity.
 2. The method ofclaim 1, wherein the desulfurization system produces one or more fuelproducts with a sulfur content to 30 ppm or less.
 3. The method of claim2, wherein the desulfurization system reduces one or more fuel product'ssulfur content to a level in compliance with a published governmentstandard.
 4. The method of claim 1, wherein the modem reformer producesa higher percentage of high octane gasoline per barrel in comparison tothe percentage produced by the refinery using the at least onehydrocarbon reformer and the desulphurization system.
 5. The method ofclaim 4, wherein the increase in the percentage of high octane gasolineproduced per barrel of is greater than about 3-5% per barrel.
 6. Themethod of claim 5, wherein the increase in the percentage of high octanegasoline produced per barrel is between 5% to 27%.
 7. The method ofclaim 5, wherein the increase in the percentage of high octane gasolineproduced per barrel is from about 60-80% for the fuel catalytic reformerto about 90-98% for the high efficiency catalytic cracking reformer. 8.A method for reducing the sulfur content of diesel fuel and gasoline ina fuel production process to comply with government standards,comprising the steps of: converting at least two catalytic reformerunits into hydrodesulfurization units; adding a continuous catalyticreformer to the refinery infrastructure; and wherein the net presentvalue of fuel produced by the fuel production process using the CCR andthe desulfurization systems, is greater than the net present value ofthe fuel produced by the fuel production process using at least twocatalytic reformers.
 9. The method of claim 8, wherein thedesulfurization system reduces the sulfur content of the gasolineproduced by the refinery to about 30 ppm or less.
 10. The method ofclaim 8, wherein the desulfurization system reduces the sulfur contentof the diesel fuel produced by the refinery to about 15 ppm or less. 11.The method of claim 8, wherein the hydrodesulfurization system reducesthe sulfur content of the gasoline and diesel fuel produced by therefinery to levels in compliance with a published government standard.12. The method of claim 8, wherein the CCR reformer increases in therefinery's overall output of a gasoline product, an ultra low sulfurdiesel product, produced per barrel, or both, and the desulfurizationsystems enable the refinery to reduce the sulfur content of the lowsulfur gasoline and ultra low sulfur diesel produced to about 30 ppm orless and about 15 ppm or less respectively.
 13. The method of claim 12,wherein the increase in the overall output as a percentage of a highoctane fraction produced per barrel is greater than about 5%.
 14. Themethod of claim 12, wherein the increase in the percentage of highoctane gasoline produced per barrel is between 5% to 27%.
 15. The methodof claim 12, wherein the increase in the percentage of high octanegasoline produced per barrel is from about 60-80% for the at least twocatalytic reformers to about 90-98% for the CCR reformer.
 16. A methodfor producing low sulfur gasoline and ultra low sulfur diesel in arefinery process having a gasoline production stream, a diesel fuelproduction stream, or both, with said streams having as part of theirrefining production streams at least one reforming step, comprising:converting the at least one reforming step of the gasoline productionstream into one or more hydrodesulfurization steps, and replacing the atleast one reforming step in the process with a higher efficiencycatalytic reforming step, to produce an increase in value of theproduction stream or streams which offsets at least in part an initialcost for the step of converting the at least one reforming step of thegasoline production stream into one or more hydrodesulfurizationsystems.